Downhole compressor for charging an electrical submersible pump

ABSTRACT

Downhole Electric Submersible Pumps (ESP) in a production string often experience gas lock caused by free gas present in the production liquids which reduces the intake pressure below operating parameters of the ESP. A compressor is disclosed for compressing production fluid prior to feeding the production fluid into an ESP intake. The compression entrains or dissolves free gas into the production liquid, reducing the risk of gas lock of the ESP. The compression increases production fluid pressure to within the operating pressure of the ESP intake, to a selected pressure, or to above the free gas bubble point.

CROSS-REFERENCE TO RELATED APPLICATIONS

None.

FIELD OF INVENTION

The disclosure generally relates to production of hydrocarbon-bearingfluids from a wellbore extending through a subterranean reservoir. Moreparticularly, the disclosure addresses apparatus and methods forcompressing produced fluids having both liquid and free gas componentsprior to intake into an electrical submersible pump.

BACKGROUND OF INVENTION

In the production of hydrocarbons from a wellbore extending through ahydrocarbon-bearing zone in a reservoir, a production string or tubingis positioned in the wellbore. A production string can include multipledownhole tools, pipe sections and joints, sand screens, flow and inflowcontrol devices, etc. To pump production fluid to the surface, anelectrical submersible pump (ESP), powered by an electric motor througha drive shaft, is positioned downhole in the wellbore. Electrical poweris usually provided from a surface source by a power cable extending tothe downhole electric motor. Additional tools used in conjunction withan ESP and electric motor include seal subassemblies, protectors, sensorassemblies, gas separators, additional pumps, standing valves, etc. Theelectric motor powers the pumps, separators, etc., via a drive shaftconnected to the rotary elements of these devices.

A submersible pump can see dozens of shut-offs each year for variousreasons. Unwanted and nuisance shut-offs include those caused by gaslock, a condition in pumping and processing equipment caused byinduction of free gas. The presence of compressible gas interferes withoperation of the pump, thereby preventing intake of production fluid.The production fluid often contains two or more fluids. Gas can be founddissolved in the production fluid or merely mixed, in a gaseous phase asfree gas, with production liquids. The free gas can exist in situ in thereservoir or can evolve during production as pressure drops below thebubble point.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the features and advantages of thepresent invention, reference is now made to the detailed description ofthe invention along with the accompanying figures in which correspondingnumerals in the different figures refer to corresponding parts and inwhich:

FIG. 1 is a schematic view of an exemplary well system utilizing anembodiment of a compressor assembly disclosed herein;

FIG. 2 is a schematic partial view of an exemplary tubing string havingvarious downhole tools thereon, including a submersible pump and motorfor use in conjunction with a compressor assembly according to thedisclosure; and

FIG. 3 is a cross-sectional, schematic view of an exemplary compressorassembly according to an aspect of the disclosure.

It should be understood by those skilled in the art that the use ofdirectional terms such as above, below, upper, lower, upward, downwardand the like are used in relation to the illustrative embodiments asthey are depicted in the figures, the upward direction being toward thetop of the corresponding figure and the downward direction being towardthe bottom of the corresponding figure. Where this is not the case and aterm is being used to indicate a required orientation, the Specificationwill state or make such clear.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

While the making and using of various embodiments of the presentdisclosure are discussed below, a practitioner of the art willappreciate that the disclosure provides concepts which can be applied ina variety of specific embodiments and contexts. The specific embodimentsdiscussed herein are illustrative of specific ways to make and use thedisclosed apparatus and methods and do not limit the scope of theclaimed invention.

As used herein, the words “comprise,” “have,” “include,” and allgrammatical variations thereof are each intended to have an open,non-limiting meaning that does not exclude additional elements or steps.It should be understood that, as used herein, “first,” “second,”“third,” etc., are arbitrarily assigned, merely differentiate betweentwo or more items, and do not indicate sequence. Furthermore, the use ofthe term “first” does not require a “second,” etc.

The terms “uphole” and “downhole,” “upward” and “downward,” and thelike, refer to movement or direction with respect to the wellhead,regardless of borehole orientation. The terms “upstream” and“downstream” refer to the relative position or direction in relation tofluid flow, irrespective of the borehole orientation. Although thedescription may focus on particular means for positioning tools in thewellbore, such as a tubing string, coiled tubing, or wireline, those ofskill in the art will recognize where alternate means can be utilized.Directional terms, such as “above” and “below” may also be used withrespect to the Figures as shown and so do not limit to the orientationof the assembly or tool in use.

FIG. 1 is a schematic illustration of a well system, indicated generally10, having a gas compressor assembly according to an embodiment of thedisclosure. A wellbore 12 extends through various earth strata,including at least one production zone 20. Exemplary wellbore 12 has asubstantially vertical section 14 and a substantially deviated section18, shown as horizontal, which extends through a hydrocarbon-bearingsubterranean zone 20. As illustrated, the wellbore is cased with acasing 16 along an upper length. The wellbore is open-hole along a lowerlength. The disclosed apparatus and methods will work in variouswellbore orientations and in open or cased bores.

Positioned within wellbore 12 and extending from the surface is aproduction tubing string 22. Typically the production tubing string ishung from or attached to the casing or wellhead. The production tubingstring 22 provides a conduit for production fluids to travel from theformation zone 20 up to the surface. Positioned within the string 22 invarious production intervals adjacent to the zone 20 are a plurality ofproduction tubing sections 24. Annular isolation devices 26, such aspackers, provide annular seals to fluid flow and differential pressurein the annulus defined between the production tubing string 22 and thecasing 16. The areas between adjacent isolation devices 26 defineproduction intervals.

In FIG. 1, the production tubing sections 24 include sand controlcapability such as sand control screen elements to allow productionfluid to flow therethrough but filter particulate matter of sufficientsize. Other tools and mechanisms can be used in conjunction with theproduction string along the production zone, such as flow controldevices, autonomous flow control devices, check valves, protectiveshrouds, sliding sleeve valves, etc. Such elements are well known in theindustry.

The production string allows production fluid to enter the string. Theproduction fluid can have multiple components, such as oil, water,natural gas and other gases, in varying proportions. Further, thecomposition of the production fluid can vary between productionintervals. The term “natural gas” as used herein means a mixture ofhydrocarbons and varying quantities of non-hydrocarbons that exist in agaseous phase at room temperature and pressure. The term does notindicate that the natural gas is in a gaseous phase at the downholelocation of the inventive systems. Where it is intended to refer to asubstance in a gaseous phase, the terms “free gas,” “gaseous phase,” orsimilar, is used. It is to be understood that at formation pressure andtemperature, natural gas may exist dissolved in a liquid or mixed with aliquid. Such natural gas can evolve to a gaseous phase, for example, inthe production string under lower pressures or temperatures. Thedisclosed apparatus and methods are useful to entrain or dissolveevolved free gas into the liquid components of the production fluid.

The production tubing string seen in FIG. 1 also includes an exemplaryand schematic “tool stack” 28 or series of tools for managing productionfluid downhole and pumping production fluid to the surface. The toolspresented are exemplary, non-limiting, and are discussed with furtherrespect to FIG. 2.

FIG. 2 is a schematic view in elevation of an exemplary tubing stringhaving various downhole tools thereon, including a submersible pump andmotor for use in conjunction with a gas compressor assembly according tothe disclosure.

The tubing string 30 includes multiple downhole tools connected to oneanother and positioned below a string of tubulars 32 extending to thesurface. The exemplary tubing string 30 includes a sensor assembly 34,an electric motor assembly 36, a seal subassembly 38, a protectorassembly 40, a gas separator assembly 42, a gas compressor assembly 44,and an electrical submersible pump assembly 46. Additional tools can beemployed, including multiple pumps, separators, and protectors. Thetools are connected to one another using threaded connections or otherconnection mechanisms. Attached to and extending below the illustratedstring is a production string extending through one or more productionzones of the reservoir and typically having sand screens, flow controldevices, inflow control devices, valves, and the like, and into whichproduction fluid from the reservoir flows. The ESP assembly pumps theproduction fluid to the surface via tubulars 32.

The sensor assembly 34 can be of various types for measuring variousdownhole environmental or motor characteristics. Preferably the sensorassembly includes pressure and temperature sensors. Measurements areconveyed to the surface by wire or wirelessly, providing the motoroperator data for use in controlling the motor. A preferred sensorassembly includes a surface transceiver module, a surface safety choke,downhole temperature and pressure sensors, and various adapters,connectors, and power sources. The sensors are connected to the ESPmotor 50. A preferred sensor assembly includes a temperature sensor formeasuring fluid temperature, a motor oil temperature sensor, and motorwinding temperature sensor. A pressure sensor measures fluid pressure atthe sensor location. Optionally, a vibration sensor, measuring vibrationon three axes, is also present. The transceiver module provides power toand receives measurement data from the sensors. The measurements areconveyed to the surface. Preferably, the system automatically shuts downwhen measurements exceed a pre-determined and pre-programmed maximum.Sensor systems are commercially available, such as the sensor systemssold as Global or Halliburton Artificial Lift Sensor Systems, availablefrom Halliburton Energy Services, Inc.

The electric motor assembly 36 includes a housing 48 and a rotaryelectric motor 50 having a drive shaft 52 extending therefrom. Theelectric motor is powered by electricity delivered along power cable 54extending from the surface. The cable is typically disposed in aprotective conduit and can run either along the interior or exterior ofthe string. Electric ESP motors are commercially available, for example,from Halliburton Energy Services, Inc. The motor specifications areselected based on operating and well conditions as will be understood bythose of skill in the art. The ESP motor 50 is connected to the sensorsystem and is typically controlled by a motor operator and has selectedautomatic shut-offs based on sensor data. The drive shaft 52 extendsfrom the upper end of the motor and drives the separators, compressors,and ESPs on the production string.

The seal sub 38 and protector 40, sometimes also referred to as a seal,can serve to prevent production fluid or contaminants from entering theESP motor 36 by equalizing interior and exterior pressure, provide adielectric or other acceptable motor oil reservoir, conduct heat awayfrom the motor, and compensate for pressure to absorb thermal expansion.A thrust bearing accepts fluid column load upon start-up and absorbsaxial load of the ESP pump 46. Protectors are available in varying sizesand weight specifications and varying configurations, includinglabyrinth, pre-filled, single, double and modular bag, or combinationsarranged in series or parallel. Further, models are available forhigh-load thrust bearing and high-strength shaft. Protectors arecommercially available from Halliburton Energy Services, Inc. One ormultiple seals or protectors can be employed on an ESP productionstring.

The gas separator assembly 42 is positioned up-hole from the protector40, and, like the protector, can be employed as a single unit ormultiple stacked units. A gas separator typically imparts a rotation tothe production fluid to liberate free gas from the production fluid. Thefree gas is then vented to the wellbore annulus via one or more outlets.This reduces produced free gas, disposal of unwanted gas production,workload of the ESP and ESP motor, and the volume of productionnecessary to produce a given quantity of oil. The separator is driven bythe ESP motor 36 via drive shaft. Gas separators are known in the artand commercially available, for example, from Halliburton EnergyServices, Inc.

The gas compressor assembly 44 is positioned between the separator 42and ESP assembly 46. The gas compressor assembly 44 is discussed indetail below with reference to FIG. 3. Generally, the compressorreceives production fluid through an intake and, via centrifugal forces,compresses it to reduce or eliminate free gas in the fluid. Thecompressor also raises fluid pressure prior to discharge into the ESP 46such that the ESP intake is “pre-charged” or “charged” to a pressurewithin its operating range. The centrifugal force produced by thecompressor entrains free gas into a gas-liquid mixture and dissolves gasinto the production liquid. The compressor is preferably powered by theESP motor via a drive shaft although alternative power sources can beapplied. Production fluid entering the compressor proceeds throughmultiple compressor stages, with fluid pressure increased at each stage.Stages are arranged in series to produce a desired fluid pressure upondischarge to the ESP intake.

Further, the compressors provide increased fluid pressure withoutrestricting fluid flow; that is, the compressor does not utilizing arestrictor plate, orifice plate, back-pressure device, diffuser, orother mechanism to restrict fluid flow. Where such mechanisms are used,the restriction becomes a high-wear point and is susceptible to failuredue to erosion, especially when the production fluid a high sandcontent. Erosion can result in cutting of the tool in two, with aresultant loss of the lower portion of the tool and any tools connectedbelow. A fishing trip to retrieve the dropped string is expensive andtime consuming. Further, such restrictions tend to plug with debris,such as rubber from previously run units. The compressor 44 handlesdebris more easily, eliminates high-erosion points at restrictions,reduces the likelihood of failure due to erosion, and prolongs theuseful life of the tool. The compressor design does not restrict orlimit fluid flow, or hydrocarbon production, to increase fluid pressure,as will be seen in relation to FIG. 3.

The ESP assembly 46 pumps production fluid to the surface. The ESPintake receives fluid from the last sequential compressor 44 at apressure within the operating limits of the ESP, eliminating or reducingthe risk of gas lock. The ESP is preferably rotated by a drive shaftpowered by the motor 36. Alternate power sources can be employed. Forcentrifugal ESPs, the number of stages determines the total liftprovided and determines the total power required for operation. Sensorsand instrumentation can be employed to provide operating condition datato the operator or for automatic operation. For example, automaticshut-down sensors can be used to limit potential damage from unexpectedwell conditions. ESP specifications include a minimum fluid pressurerequirement at the pump intake. The compressor 44 (or multiplecompressors in series) is selected to provide production fluid to theESP intake within its operating range.

FIG. 3 is a cross-sectional schematic view of an exemplary compressorassembly according to an aspect of the disclosure. An exemplarycompressor 60 is seen having three stages or sections 62 a-c arranged inseries. Each stage increases the pressure of the production fluid. As anexample, the first compressor stage 62 a increases pressure by 8 psi (55kPa), the second compressor stage 62 b further increases pressure by 16psi (110 kPa), and the third compressor stage 62 c further increasespressure by 24 psi (165 kPa), resulting in a total increase across thecompressor of approximately 48 psi (331 kPa). Additional stages, orstages increasing the pressure by greater amounts, can be employed toachieve higher total increase of fluid pressure. For example, in apreferred embodiment, the pressure is raised by about 16 psi (110 kPa)to 65 psi (448 kPa), and more preferably by about 40 psi (276 kPa) to 60psi (414 kPa). The stages are selected to increase the production fluidpressure to a pressure within the operating range of the ESP, therebypreventing gas lock. Additional or fewer stages can be employed basedupon required ESP intake pressure.

A tubular compressor housing 68, preferably generally cylindrical asshown, is attached to a base assembly 70 and a head assembly 72 via lockplates 74. The lock plates can be replaced or supplemented with otherconnection mechanisms, such as threaded connectors, pins, welds, and thelike. A compression tubular 76, made-up of a plurality of tubulars 76a-c, is positioned interior to the housing 68. The compressor, in thisembodiment, has three compressor stages 62 a-c, although fewer or morecan be used. Above and below each stage 62 is preferably positioned ashaft support assembly 78 for supporting compressor shaft 80 whichextends the length of the compressor 60. The compressor housing 68 ispreferably made of corrosion-resistant material such as carbon steel or9 chrome 1 molly. The compression tubular 76 is preferably made ofstainless steel or other material having the strength required toprevent collapse of the tool assembly.

The base assembly 70 and head assembly 72 are each comprised of agenerally tubular housing which can be connected to tools or additionaltubulars, such as by bolt assemblies 82 and 84, respectively. Alternateconnections can be used as are known in the art. The base assemblydefines an interior passageway 86, forming an intake 88 for thecompressor assembly, providing fluid communication with a tool below,such as gas separator 42. The base interior passageway 86 delivers fluidinto the intake of the first compressor stage 62 a. Similarly, the headassembly 72 defines interior passageway 90, having an intake forreceiving fluid from the third compressor stage 62 c. The head assemblyforms a discharge outlet 92 for the compressor assembly, which deliverscompressed fluid from the third compressor stage 62 c to a tool ortubular positioned above, such as ESP assembly 46.

The rotary shaft 80 extends the length of the compressor assembly andcauses rotation of each of the three stages 62 a-c. The shaft issupported by multiple support assemblies 78 a-d. At the upper and lowerends of the shaft are connections 94 for connection to similar shaftspositioned in adjacent tools, such as gas separator 42 and ESP assembly46. The shaft can be specialized for high-torque systems and ispreferably of corrosion-resistant material. The shaft can be monolithicor formed of several connected shaft components. The shaft is driven bythe drive shaft 52 of the electric motor 50.

The three stages 62 a-c are of similar construction and design. Thefirst stage 62 a is discussed in detail, with the remaining stageshaving similar components and functions. The first stage 62 a has ahelical blade 100 a extending radially outward from a compressor sleeve102 a. The sleeve 102 a forms a tubular and is positioned about andattached to a section of the shaft 80. (Alternately, the helical bladecan be formed about a portion of the shaft itself.) The rotary blade andsleeve can be formed of a plurality of adjacent units for ease ofmanufacture and assembly. Rotation of the shaft 80 results in rotationof the sleeve 102 a and helical blade 100 a. Production fluid receivedfrom the base assembly passageway 86 is received into the first stage,where the rotation of the helical blade 100 a causes the fluid torotate, thereby increasing the fluid pressure. Existent free gas in theproduction fluid is dissolved into or entrained with production liquids.The pressurized fluid is then output to a subsequent stage, such asstage 62 b, for further treatment, or through the discharge headpassageway 90 to a tool assembly positioned above, such as ESP 46. Thefluid pressure is preferably increased by an incremental amount suchthat the stage remains relatively small. For example, an exemplary fiststage 62 a is approximately four inches in diameter, twelve inches inlength, and imparts a pressure increase of approximately 8 psi (55 kPa).

The helical blade 100 a extends radially outward from the sleeve 102 a(or shaft). The blade is “wrapped” about the sleeve, forming a helicalshape. The blade appears to be wrapped although other manufacturingmethods (e.g., casting) can be used to make the unit. The stage isspecifically designed to increase fluid pressure, or add lift or head.To that end, the compressor helical blade 100 a is positioned in theinterior passageway 104 a defined by the compression tubular 76 a, witha relatively small clearance. For example, in a preferred embodimentwhere the compressor helical blade is inserted into a tube, the radialclearance is about 0.144 inches (0.366 cm) in a 3.75 inch (9.53 cm)diameter bore. In another preferred embodiment, the compressor blade ispositioned in a honed bore, allowing for better tolerances and reducedclearances. For example, in a honed bore a preferred clearance isapproximately 0.003 inches (7.62 mm) in a 3.75 inch (9.53 cm) diameterbore. The tight clearance reduces annular bleed-by of gaseous and liquidfluids which, if present, decreases the effectiveness and the head addedto the fluid by the compressor helical blade. The increasedeffectiveness allows an equivalent amount of head to be added to theproduction fluid using a lower motor rate (rpm), thereby saving energy,reducing operating temperatures of the motor, decreasing burn-out, etc.In a preferred embodiment, the compressor blade is operated in a rangeof 3500 to 4500 rpm using an electric motor positioned downhole. Inaddition to reducing bleed-by due to excessive blade clearance, theblade is mounted in the only tubular through which the production fluidflows at this section of the string. That is, there is no annular spacebetween the compression tube 76 a and the housing 68 through which fluidmay flow or bypass the compressor blade. Finally, the preferredembodiment is difficult to impossible to plug during use with coalfines, sand, etc. The helical compressor blade will elevate or movefines and the like during rotation. The tight radial clearance will notallow debris accumulation along the compression tube wall. Additionally,the helical blade 100 does not flatten out into substantially vertical,radially extending paddles at any point. Such paddles create a fluidvortex, agitate the fluid, and decreases the effectiveness of the bladein increasing fluid pressure or lift. For a cross-reference, see USPatent Application Publication 2012/0269614, to Bassett, which is herebyincorporated for all purposes.

The second stage 62 b and third stage 62 c operate in a similar fashion,each causing rotation of the production fluid, incrementally increasingthe fluid pressure, and dissolving or entraining existent free gas. Inan exemplary embodiment, the second stage imparts an additional 16 psi(110 kPa) and the third stage imparts an additional 24 psi (165 kPa) tothe fluid. The production fluid is discharged to the ESP atapproximately 48 psi (331 kPa) or greater and within the pressurerequirements for the ESP intake.

Positioned above and below each stage are shaft support assemblies 78a-d. In use, the shaft support assemblies support the shaft 80,preventing axial bending of the shaft. The shaft support assemblies 78 aand 78 d are positioned, respectively, in the base 70 and head 72, whilethe shaft support assemblies 78 b-c are positioned in the compressiontubular 76. Alternate arrangements are possible as will be understood bythose of skill in the art. For purposes of discussion, shaft supportassembly 78 c is considered in detail.

Shaft support assembly 78 c has a bearing housing 110 c with a supportsleeve 112 c and bushing 114 c positioned therein. The bearing housing110 c is mounted within a support compression tubular 116 c. The supportcompression tubular 116 c forms part of the compression tubular 76. Thedesign shown provides ease of assembly, however, other arrangements willbe readily apparent to those of skill in the art. For example, thecompression blades, support assemblies, etc., can be internally mountedinto a single compression tubular. In a preferred embodiment, thesupport assembly, or portions thereof, is made of corrosion-resistantmaterials. For example, the support tubular 116 is preferably of acorrosion-resistant nickel alloy and the sleeve 112 and bushing 114 areof tungsten carbide. Alternate corrosion and erosion-resistant materialsand methods will be readily apparent to those of skill in the art.

The compressor assembly, or charger, is designed for use with productiontubing and mounted below one or more ESPs, although additional uses willbe apparent to those of skill in the art. Preferably the compressorincludes more than one stage, with each successive stage incrementallyincreasing the fluid pressure to a desired pressure range correspondingto the intake specifications of the ESP into which the fluid isdischarged. Production fluid enters the wellbore annulus and, typicallyafter flowing through screens or filters, into an interior passageway orbore in the production string. The fluid flows towards the surface,through a series of downhole tools. For example, in an exemplaryproduction string, the production fluid flows through a sensor assembly,a motor assembly, one or more seal subs, one or more protectors, one ormore gas separators, a gas charger of one or more stages as disclosedherein, and one or more ESPs, and thence to the surface. Preferably themotor powers, by a drive shaft connected to tool assembly shafts, theplurality of powered tools, including the gas separator, gas charger,and ESP, for example. The motor receives electrical power from thesurface via cable in a preferred embodiment.

The compressor can be used at any well depth, typically ranging from 500feet to over 13,000 feet deep. The gas charger is expected to be mosteffective in wells producing production fluid at or below 1250 barrelsper day, and down to as little as 150 bpd. It is also anticipated thatthe compressor will be of greater use in wells producing larger volumesof free gas, where the compressor will entrain or dissolve the free gasinto the production liquid. The compressor can vary in size. In apreferred embodiment, a compressor tool is approximately four inches indiameter and approximately 36 inches in length per section. Overalllength, obviously, is dependent on the number of stages employed. Thecompressor design also reduces the likelihood of plugging due to debrisin the production fluid. The helical design of the compressor blade 100provides a greater flow area than alternative compressors havingimpellers and diffusers.

Among the preferred embodiments, various methods or processes aredisclosed and addressed as steps. The steps are not exclusive and can becombined in various ways, with steps omitted, added, re-ordered, and/orrepeated, as will be recognized by those of skill in the art. Themethods are limited only by the claims as construed by applicable law.The following methods are numbered for ease of reference and areexemplary in nature. 1. A method of producing fluid from a subterraneanwell having a wellbore extending through a hydrocarbon-bearingformation, the method comprising the steps of: positioning at a downholelocation in the wellbore a work string having an electric motor, acompressor assembly, and an Electric Submersible Pump (ESP); operatingthe compressor assembly and the ESP using the electric motor; pumpingproduction fluid from the formation and into an interior passageway ofthe work string, the production fluid having both free gas andproduction liquid therein; compressing the production fluid using thecompressor assembly, and entraining or dissolving at least a portion ofthe free gas into the production liquid; and feeding the compressedproduction fluid to an intake of the ESP. 2. The method of claim 1,wherein the step of compressing further comprises compressing theproduction fluid to an intake pressure within the operating range of theESP intake. 3. The method of claims 1-2, wherein the step of compressingfurther comprises compressing the production fluid by between about 8psi (55 kPa) and 60 psi (414 kPa). 4. The method of claims 1-3, whereinthe step of compressing further comprises compressing the productionfluid to a pressure above the free gas bubble point at the downholelocation. 5. The method of claims 1-4, wherein the step of compressingfurther comprises compressing the production fluid in multiple stages inthe compressor assembly, and wherein each of the multiple stagescompresses the production fluid by between about 8 psi (55 kPa) and 32psi (221 kPa). 6. The method of claims 1-5, wherein the compressorassembly is positioned in the string between the electric motor and theESP. 7. The method of claims 1-6, further comprising the step of pumpingthe compressed production fluid to the surface. 8. The method of claims1-7, wherein the compressor assembly includes a rotary compressorelement attached to a compressor drive shaft, and further comprising thestep of driving the rotary compressor drive shaft by a drive shaft ofthe electric motor. 9. The method of claims 1-8, further comprising thestep of separating at least some free gas from the production fluidusing a gas separator tool prior to the step of compressing theproduction fluid using the compressor assembly. 10. The method of claims1-9, wherein the compressor assembly allows fluid flow therethroughwithout fluid flow restriction. 11. The method of claims 1-10, whereinthe step of compressing further comprises the step of supporting a driveshaft of the compressor assembly with at least one bearing. 12. Themethod of claim 11, wherein the at least one bearing comprises acorrosion-resistant bushing.

Persons of skill in the art will recognize various combinations andorders of the above described steps and details of the methods presentedherein. While this invention has been described with reference toillustrative embodiments, this description is not intended to beconstrued in a limiting sense. Various modifications and combinations ofthe illustrative embodiments as well as other embodiments of theinvention, will be apparent to persons skilled in the art upon referenceto the description. It is, therefore, intended that the appended claimsencompass any such modifications or embodiments.

What is claimed is:
 1. A method of producing fluid from a subterranean well having a wellbore extending through a hydrocarbon-bearing formation, the method comprising the steps of: positioning at a downhole location in the wellbore a work string having an electric motor, a compressor assembly, and an Electric Submersible Pump (ESP); operating the compressor assembly and the ESP using the electric motor; pumping production fluid from the formation and into an interior passageway of the work string, the production fluid having both free gas and production liquid therein; compressing the production fluid using the compressor assembly, and entraining or dissolving at least a portion of the free gas into the production liquid; and feeding the compressed production fluid to an intake of the ESP.
 2. The method of claim 1, wherein the step of compressing further comprises compressing the production fluid to an intake pressure within the operating range of the ESP intake.
 3. The method of claim 1, wherein the step of compressing further comprises compressing the production fluid by between about 8 psi (55 kPa) and 60 psi (414 kPa).
 4. The method of claim 1, wherein the step of compressing further comprises compressing the production fluid to a pressure above the free gas bubble point at the downhole location.
 5. The method of claim 1, wherein the step of compressing further comprises compressing the production fluid in multiple stages in the compressor assembly, and wherein each of the multiple stages compresses the production fluid by between about 8 psi (55 kPa) and 32 psi (221 kPa).
 6. The method of claim 1, wherein the compressor assembly is positioned in the string between the electric motor and the ESP.
 7. The method of claim 1, further comprising the step of pumping the compressed production fluid to the surface.
 8. The method of claim 1, wherein the compressor assembly includes a rotary compressor element attached to a compressor drive shaft, and further comprising the step of driving the rotary compressor drive shaft by a drive shaft of the electric motor.
 9. The method of claim 1, further comprising the step of separating at least some free gas from the production fluid using a gas separator tool prior to the step of compressing the production fluid using the compressor assembly.
 10. The method of claim 1, wherein the compressor assembly allows fluid flow therethrough without fluid flow restriction.
 11. The method of claim 1, wherein the step of compressing further comprises the step of supporting a drive shaft of the compressor assembly with at least one bearing.
 12. The method of claim 11, wherein the at least one bearing comprises a corrosion-resistant bushing.
 13. The method of claim 1, wherein the step of compressing the production fluid using the compressor assembly, further comprises rotating a helical compressor blade within a compressor tubular.
 14. The method of claim 13, wherein a clearance between the helical compressor blade and the compressor tubular is minimized.
 15. The method of claim 13, wherein all production fluid in the interior passageway is compressed in the compressor assembly.
 16. An apparatus for lifting production fluid from a subterranean wellbore extending through a hydrocarbon-bearing formation to the surface, the apparatus comprising: an Electrical Submersible Pump (ESP) having a fluid intake; a compressor having at least one compressor stage for compressing production fluid, the compressor stage having a fluid discharge in fluid communication with the ESP fluid intake, a generally helical compressor blade mounted for rotation in a generally cylindrical chamber, and wherein the compressor blade entrains or dissolves a free gas component of a production fluid into a liquid component of the production fluid; and an electrical motor for powering the ESP and compressor.
 17. The apparatus of claim 16, further comprising a plurality of adjacent compressor stages arranged in series, with each compressor stage discharging fluid to an intake of an adjacent compressor stage or to the ESP intake.
 18. The apparatus of claim 17, wherein the plurality of compressor stages, in combination, increase pressure of the production fluid to a pressure within the operating range of the ESP intake.
 19. The apparatus of claim 16, wherein each compressor stage increases production fluid pressure by between about 8 psi (55 kPa) and 32 psi (221 kPa).
 20. The apparatus of claim 16, wherein the one or more compressor stages increase production fluid pressure by between about 8 psi (55 kPa) and 60 psi (414 kPa).
 21. The apparatus of claim 16, wherein a compressor stage further comprises at least one compressor shaft operably connected to a drive shaft of the electric motor, and at least one compressor shaft bearing. 